The bulk of the electrical power consumed is provided by electrical utilities which utilize steam-driven turbines to drive generating means at central generating stations, and a network of transmission and distribution lines to distribute the power to widely dispersed sites where it is used. This method of power supply entails large energy losses. For instance, approximately 70% of the heat energy of fossil fuel burned at a central station is not utilized but is disposed of as waste heat. Further losses occur in the transmission and distribution of the electrical energy. These losses are reflected in the rates charged by electrical utilities.
In order to reduce electricity users' energy costs, so-called cogenerators have been provided. These cogenerators include a heat engine which drives electrical generating means, the output of which is coupled to the electrical lines servicing the electrical loads at the user's site. Such systems typically include one or more heat exchangers for distributing the heat output of the heat engine to thermal loads at the user's site, such as for heating of buildings. The use of such heat, which would otherwise be wasted, can raise the overall efficiency of utilization of the heat content of fuel to perhaps 80%; the energy cost savings to the cogenerator user are primarily attributable to reduction of energy costs for the uses, such as building heating, to which the cogenerator heat output is put.
However, known cogenerator systems are deficient in certain regards by failing to take into account the nature of the costs of using utility-supplied electricity. Utilities must provide generating, transmission, and distribution capacity sufficient to service the maximum total demand of all their connected customers. This demand tends to follow a daily cycle with a peak in the middle of the day, and a seasonal cycle, with a peak in the summer in moderate and warm climates, and a peak in the winter in colder regions. The equipment or generating capacity necessary to supply the peak demand is not always in use; nonetheless, the cost of having it available must be borne by the utility's customers. Utilities attempt to apportion such cost among their customers according to their respective peak usage by basing their electricity charges for individual customers upon their peak demand. For instance, utilities may charge different rates for electrical energy used during predetermined peak, intermediate, and off-peak periods during the day. Utilities may also impose a peak power demand charge based on the customer's peak power demand during a predetermined demand measuring period, such as during a 15 minute period each day. In addition to or instead of such peak demand charges, a utility may adjust its energy rates according to the customer's measured peak power demand. Moreover, utilities may base their rates and charges to a customer for an extended period such as an entire year on peak demand measured at a particular time, e.g. on a measured summer peak. Thus, heavy demand coinciding with a demand measuring period may grossly affect a customer's utility charges for that month, or even the following year. The customer's difficulty is compounded by the fact that utilities generally measure peak demand by peak-registering meters which are enabled during the demand measuring period and periodically read by the utility; the customer is therefore unable to determine when the peak occurred or verify what the peak in fact was. The customer has no means to control his demand and usage of utility power and energy or to verify the utility's basis upon which he is billed.
Known cogeneration systems, which lack the ability to control cogenerator operation in response to time of day and/or power being supplied to the site by the utility, cannot, for instance, ensure that the cogenerator is operating during peak rate periods or that it will control the peak usage of power from the utility. Such measures would significantly affect the customer's energy costs. Moreover, utility customers with cogeneration systems cannot determine the energy cost savings obtained by operation of the cogenerator, or whether in fact there are any savings. For instance, the apparatus set forth in U.S. Pat. No. 3,944,837 provides thermostatic control of the cogenerator and turns the heat engine on or off to control the temperature of the heat exchange medium, thereby matching the cogenerator thermal output to the site thermal demand. Such apparatus is entirely unresponsive to conditions affecting utility costs. For example, such apparatus may be inactive when there is low thermal demand but high electrical demand during a peak rate period, and be fully active when there is high thermal demand during an off-peak rate period. As a consequence, such systems do not optimize their operator's energy costs, particularly when their capital costs are taken into consideration. Known commercial systems also do not measure their power outputs, although some which operate at full output when on accumulate engine run time data, which when multiplied by the rated output, coarsely approximates total output.